Reduced fouling of steam turbines by treatment with sulfur containing compounds



United States Patent O 3,422,022 REDUCED FOULING F STEAM TURBINES BYTREATMENT;v WITH SULFUR CONTAIN- ING COMPOUNDS James H. Richards,Holland, Pa., assignors to Betz Laboratories, Inc., Philadelphia, Pa., acorporation of Pennsylvania No Drawing. Filed Oct. 27, 1966, Ser. No.589,795

US. Cl. 252181 Int. Cl. C22f 11/16; C231 11/00 ABSTRACT OF THEDISCLOSURE A ,method of eliminating, reducing, or inhibiting the foulingof steam turbines and in particular, the controlling of fouling which isdue to the presence of contaminants in the steam by dispersing in thesteam employed to operate a turbine between one to fifty parts by weightof a sulphur compound selected from the group consisting of sodium acidsulphite, ethylene sulphite, sodium bisulphate, sodium sulfoxylatedformaldehyde, sodium formaldehyde bisulfite and morpholine sulphate foreach part by weight of the contaminant contained in the steam.

BACKGROUND OF THE INVENTION The fouling of steam turbines, while variousattributed to a number of different causes and phenomena, is a real andaggravated problem. Such fouling generally affects the turbine, andparticularly the turbine blades, to restrict the passage of steam andconsequently impair the efficiency of operation of the turbine unit. In,addition, accumulated fouling deposits may increase the Work load to theextent that damage to, or failure of, the thrust bearings isexperienced. a

It is generally recognized that most turbine deposits comprise acombination of water soluble materials such as sodium phosphates,carbonates, and sulfates, and water insoluble silicates, which areentrained in the boiler water and/or steam and subsequently deposited inthe turbine. As a consequence of this melange of compounds ofconflicting chemical and solubility characteristics, previous attemptsto cope with turbine fouling have involved inefiicient and generallyunsatisfactory techniques. Conventional methods have employed theremoval of the water soluble constituents by means of mere washing, andthe caustic or alkaline leaching of the water insoluble silicates. Inany event, such means of controlling turbine fouling have entailedturbine operation at reduced CffiClBIlClBS, as well as the necessity forfrequent shutdowns for the purpose of removing fouling deposits.

It is an object of the present invention to provide methods for thetreatment, removal and prevention of further formation of turbinedeposites, without necessity for frequent shut-downs and cleanings.

A further object is the provision of compositions for the treatment ofthe atmosphere of steam turbines during turbine operation, whicheliminate, inhibit or reduce the formation of deposits upon the surfacesof the turbine.

The foregoing objects are achieved by means of the addition of certainorganic and inorganic sulfur containing compounds to the steam which isemployed in the turbine. The sulfur compounds employed as turbineantifoulants in the practice of the invention are:

Morpholine sulfate C H ONH- H 80 10 Claims 3,422,022 Patented Jan. 14,1969 While the precise mechanism which renders these compounds operativein the practice of the invention has not been defined, it is conceivablethat in the superheated steam environment of the turbine, thesecompositions are converted to S0 sulfuric or sulfurous acid, or hydrogensulfide, or admixtures thereof, and such conversion products accomplish,or contribute to, the achievement of the inventive goals, i.e., theelimination, preclusion or curtailment of fouling deposits in theturbine. Irrespective of the underlying theory, and as is demonstratedby subsequent data, these treating compounds do bring about theachievent of the forementioned inventive goals.

.In the practice of the invention, the above compounds are added to thesteam which is supplied to the turbine. In a preferred practice, thetreating materials are injected into the superheated steam line on theinlet or upstream side of the turbine. However, the treatments may beadded to the steam at any point between the manufacture of the steam andits introduction to the turbine, including direct feed to the turbine.Consequently, if the steam system is divided or sectionalized all of thesteam need not be treated and treatment may be limited to that steamwhich is supplied to the turbine or turbines. Since the treated systemis under pressure, the introduction or injection of the treatingmaterials must naturally be achieved at a pressure greater than thatwhich is present Within the system treated. Such injection is common inthe treatment of high pressure systems and may be achieved by a highpressure piston pump which feeds to an injection or dispersion quillpositioned in the high pressure lineor chamber to which feeding is to beaccomplished. The inlet aperture of the quill is preferably locatedwithin the atmosphere to be treated and not in proximity to the line orchamber Wall which is pierced by the quill. In those systems whichpossess a single header supplying the superheater through a distributionheader within the superheater, the treating material may be added to thesaturated steam as it leaves the boiler drum and prior to itsintroduction to the superheater system.

However, it should be noted that the treating materials may not be addedto the boiler water or boiler feed water. In the first instance,treatment of the boiler or feed water would be grossly uneconomicalsince a portion of the treating materials would be removed and discardedduring the necessary blowdown of concentrated boiler water containinghigh solids. Secondly, if the treatment is added to the boiler or feedwater, its transfer to the steam would be dependent upon carry-over.Carry-over is an undesirable phenomenon in which boiler water and itssolids content is transferred to the steam. Positive steps to preventsuch occurrence are taken in the form of chemical treatment of theboiler water, e.g., the addition of antifoam agents, and mechanicalmeans, e.g., the installation of battles. Accordingly, if the inventivetreatments were added to the boiler water, their transfer to the turbinesection would be dependent upon carry-over which would also operate toincrease the contamination of the turbine by the deposit formingmaterials which is contrary to the inventive purpose, i.e., theelimination or reduction of turbine fouling.

Experience and testing have indicated that the inventive goals arefrequently realized when the inventive treating materials are added tothe steam at a level of less than one part by weight for each onemillion parts of steam flow. However, proper treatment should be basedupon the total quantity of contaminant salts contained by the steam.Preferably between 1 to 50 parts by weight of the treating material areemployed for each part by weight of contaminating salts. It should benoted that the term contaminating salts is employed to connote thosecontaminants which are present in the boiler system as the result ofnaturally occurring contaminants in the boiling water supply, otherchemical treatments employed within the boiler system, materials derivedfrom the decomposition of the boiler components, e.g., iron and copperoxides, and intermediate contaminants formed by the decomposition ofbasic contaminants, e.g., sodium carbonate sodium oxide. Suchcontaminants may be generally defined as the salts, oxides andhydroxides of sodium, silica, iron and copper such as silicon dioxide,iron oxide, copper oxide, sodium oxide, sodium chloride, sodiumhydroxide, sodium carbonate, sodium phosphate, sodium silicate, sodiumsulfate, sodium sulfite, sodium nitrate, etc. although the exact natureand ratio of these contaminants is obviously dependent upon thecontaminants present in the boiler feed water, chemicals added to theboiler system, etc. The precise nature and quantity of such salts may bereadily determined by tests such as sodium studies which establish steampurity. Since the contaminants in the steam are normally present atlevels of less than 1 p.p.m., and usually less than 0.1 p.p.m., thequantity of treatment required will normally not exceed 50 p.p.m. andwill usually be between 0.1 to 1.0 p.p.m. of the treating materials.However, it should be noted that higher treatment levels may be employedwithout appreciably increasing the benefits provided by the invention.In this regard, excessively high treatment levels may not only removefouling deposits but may result in corrosive attack upon the metalcomponent of the turbine. The level at which such attack occurs variesfrom case to case since the dissolution of the fouling deposits ispreferential to corrosion and treating materials may be completelydissipated in the former if adequate deposits are available. In somecases, minor or controlled corrosion of the turbine may even be acceptedin preference to turbine shut-down for the purpose of removing foulingdeposits.

An additional, although secondary aspect of the present invention,concerns the control of corrosion. Specifically, morpholine sulfate,prepared by neutralizing morpholine with sulfuric acid, may be employedto provide a treating material which functions simultaneously as ananti-foulant and a corrosion inhibitor. Morpholine is released withinthe turbine and volatilized by the steam. It then serves to neutralizecorrosive agents such as carbonic acid, S

sion resistant mix and feed tanks, pumps and injection lines arerecommended.

The efiicacy of the inventive treatments 'has been thoroughly exploredand established in the treatment of duplicate two-stage, noncondensingturbines, hereafter referred to as turbines A and B, having a normalspeed of 3,600 r.p.m., and a steam rate of 30,00033,000 pounds per hour.Steam conditions of these turbines are represented by inlet steam at 600p.s.i.g. at a total temperature of approximately 700 F., with exit steamat 200 p.s.i.g. and an approximate steam temperature of 440 F. Theseconditions represent inlet steam at 200 degrees superheat and outletsteam at 50 degrees superheat.

In considering the following results, which are based primarily upon theoperating efiiciency of the turbines, it should be noted that prior tothe initiation of the inventive treatment the shut-down of each turbinefor the purpose of removing fouling deposits was required every 9 or 10days. During the inventive treatments the turbines were operated forperiods in excess of 30 days without necessity for shut-down, and inseveral instances shutdowns after days or more were found to beunnecessary when the turbines were opened and examined.

As a portion of this study, turbines A and B were both operated for 10day periods without treatment to determine what degree of impairment oftheir operating efiiciency was experienced. In all of the describedtests operating efliciency was determined by measuring the maximumnumber of revolutions which could be obtained from the turbine at noonon each test day. The results of these control tests are set forth inTable 1, below:

TABLE 1 Maximum Revolutions Percent Daily Decrease per Minute Decreasein in Operating Turbine Operating Efficiency (total 1st Day 10th DayEfiieiency percent decreasc/ N o. of days) etc., by combining with themto neutralize their acidity. 45 set forth in Table 2 below:

TABLE 2 Percent by Daily De- Weight of Quantity Quantity Maximum r.p.m.sPercent crease in I Active Inof Treatof Active Duration Yielded byTurbine Decrease Operating Percent- Turbine Active Ingredient of thegredients ment Em- Ingredient of Test in Efficiency age Im- TreatmentContained ployed Employed (Days) 1st Day Final Day Operating (Percentproveby Treat- (p.p.m.) (p.p.m.) of Test of Test Efficiency Decrease]merit merit Number of Days) A None 0 U 0 10 3, 900 3, 475 10.9 1.09 AEthylene Sulfite. 2 2. 5 0. 05 10 3, 800 3, 750 1. 3 0. 13 88 do 2 100.2 10 3, 800 3,800 0 0 100 2 10 0. 2 10 3, 850 3, 800 1. 3 0. 13 88 1000. 3 0.3 10 3, 700 3, 650 1. 3 0. 13 88 30 2 0. 6 10 3, 950 3, 900 1. 30. 13 88 2 22 5 0. 45 10 3, 750 3, 750 0 0 100 30 2 U. 6 10 3, 700 3,650 1. 3 0. 13 88 30 3 0. 9 10 3, 775 3, 700 2 0. 2 81. 6 0 0 0 10 3,850 3, 500 9. l 0.91 B Sodium Snlfoxylated 2 22. 5 0. 45 10 3, 700 3,700 0 0 I00 Formaldehyde. B Sodium Bisuliate 2 15 0.3 10 3, 755 3, 750 00 100 B Sodium Acid Sulfite. 30 3 0. 9 10 3, 850 3, 850 0 0 100 Othercorrosion inhibitors and neutralizing agents, e.g., ammonia,cyclohexylamine, etc., may also be combined with the inventivetreatments to reduce or control corrosive factors within the turbine.

For ease of feeding, relatively dilute aqueous solutions, e.g., lessthan are preferred. However, concentrated or pure treatments may beemployed and solvents, diluents and carriers other than water aresuitable although less desirable. It should also be noted that a numberof the As demonstrated by the above data, the inventive treatments haveconsistently reduced the gradual decrease in operating efiiciencyexperienced in the absence of an antifouling treatment, by between8l.6-l00%. However, this reduction in efficiency is only a portion ofthe picture. Specifically, the basic objective of the invention is anincrease in the continuous operation time of the turbine due to thereduced frequency of the necessity for turbine cleaning. Since thereduction in the efficiency of the opinventive treating materials arecorrosive and that corroeration of turbines A and B which is shown byTable l,

was such as to require the cleaning of the turbines, these day testswere employed as controls in the study discussed hereafter.Specifically, turbines A and B were treated with the inventivetreatments and continuously operated until the degree of reducedefficiency experienced in the control tests was achieved, i.e., 10.9% inrespect to turbine A and 9.1% in respect to turbine B. The results ofthis study are set forth in Table 3, below:

deposits within the turbine, improving the economic operation of steamturbines by reducing the time lost during clean-ups and the labor andmaterial involved in such cleaning operations, and providing highlyefficient and economical methods for the achievement of suchimprovements.

I claim:

1. A method for reducing the fouling of a steam tur- TABLE 3 Quantity ofPercentage Period of Percentage Chemical Decrease Continuous Increase inTurbine Chemical Treatment Employed Operating Operation Period ofRemarks (p.p.m.) Efiiciency of Turbine Continuous (Days) Operation ANone 0 10.9 10 Control. A Ethylene sulfite 0.02 10. 4 34 340 Testterminated for other reasons. A Sodium acid sulfite. 0.30 10.9 58 580 ASodium formaldehyde bisulfite. 0.45 2. 7 19 190 A... Sodium acid sulfite0. 6 7. 8 46 460 B None 0 9. 1 10 Control. B Sodium sulfoxylatedformaldehyde 0. 45 4. 7 28 280 Test terminatef for other reasons. BSodium bisulfate 0.3 7 24 240 Do. B. Sodium acid sulfite--. 0.6 5. 3 39390 Do.

It must be noted that all but one of the trials were terminated prior totheir completion due to reasons other than the necessity for removingfouling deposits from the turbine. However, in the one test which wascompleted, the continuous operation of the turbine was extended from 10to 58 days to permit the operation of the turbine to be extended bynearly 6 times the previous performance. Curves of the decrease inperformance for each of the other tests also indicate that continuousoperation could have been extended for comparable periods if the testshad been continued.

It should also be noted that while corrosion inhibition studies inrespect to morpholine sulfate have not been completed due to thenegligible corrosion rate experienced with the inventive compounds, theanti-fouling effect of this compound has been established. In addition,the release of morpholine under the conditions experienced in a steamturbine is demonstrable, and the efiicacy of morpholine in providing aneutralizing effect and inhibiting corrosion in steam environments haspreviously been established.

Another noteworthy aspect of the invention is the minute quantity oftreating material required for the elimination or curtailment offouling. For example, in the treatment of turbine B with sodium acidsulfite for a 58 day period of continuous operation, approximately41,760,000 pounds of steam were treated and employed in producing over300,000,000 revolutions of the turbine. This substantial output involvedthe utilization of only approximately 125 pounds of the chemicalemployed to treat the turbine. Viewed somewhat differently, theutilization of 125 pounds of chemical treatment, fed automatically andwith no labor requirements other than the infrequent replenishing of thechemical supply, permitted the avoidance of at least 5 shut-downs forthe cleaning of the turbine which would have been required in theabsence of the inventive treatment. The loss of operating time entailedin 5 cleaning operations as well as the expense of labor and materialsfor such cleaning, are consequently avoided by means of the utilizationof a small quantity of a relatively inexpensive chemical.

It is apparent that the applicant has provided methods and materialswhich provide an extensive improvement in greatly extending the periodin which a steam turbine may be operated between clean-ups, reducing thedecrease in the efiiciency of operation of steam turbines which isnormally caused by the formulation of fouling bine by contaminantsentrained in the steam employed to operate the turbine, comprisingdispersing within said steam between 1 to 50 parts by weight of a sulfurcompound selected from the group consisting of sodium acid sulfite,ethylene sulfite, sodium bisulfate, sodium sulfoxyL ated formaldehyde,sodium formaldehyde bisulfite and morpholine sulfate, for each part byweight of said contaminants.

2. A method as claimed by claim 1 in which sulfur compound is dispersedwithin the portion of said steam contained by said turbine.

3. A method as claimed by claim 1 in which said sulfur compound isdispersed within said steam prior to the introduction of said steam tosaid turbine.

4. A method as claimed by claim 1 in which a corrosion inhibitor is alsodispersed within said steam.

5. A method as claimed by claim 4 in which said corrosion inhibitor isselected from the group consisting of morpholine, cyclohexylamine andammonia.

6. A method as claimed by claim 4 in which said corrosion inhibitor ismorpholine.

7. A method as claimed by claim 1 in which said sulfur compound isdispersed in said steam as a dilute dispersion of said sulfur compound.

8. A method as claimed by claim 7 in which said dilute dispersion is anaqueous solution of said sulfur compound.

9. A method as claimed by claim 1 in which said sulfur compound issodium acid sulfite.

10. A method as claimed by claim 8 in which said sulfur compound issodium acid sulphite.

References Cited UNITED STATES PATENTS 2,562,549 7/1951 Hatch 252391 X2,582,138 1/1952 Lane et a1. 21-2.7 X 2,797,199 6/1957 Chittum 252-3913,042,609 7/ 1962 Hughes 252395 X MAYER WEINBLATT, Primary Examiner.

I. GLUCK, Assistant Examiner.

US. Cl. X.R.

